Canol shale fields in Northwest Territories draw global interest

CALGARY — Nobody can say with any certainty exactly how much oil is embedded in dense rock buried thousands of metres underneath frozen tundra in the central Mackenzie Valley.

But John Hogg, vice-president of exploration and operations at Calgary-based MGM Energy Corp., figures the so-called Canol shale in the Northwest Territories could hold “billions and billions of barrels” of light, sweet crude.

If it all works the way we think it will, we think this play is as viable as any of the major plays in Canada or North America

“If it all works the way we think it will, we think this play is as viable as any of the major plays in Canada or North America,” he said. “I would put it up against any one of them and say it’s as good as, if not better than, most of them.”

MGM, which holds drilling rights on 470,000 net acres in the budding resource play, estimates it alone is sitting on up to 10 billion barrels of oil in place in the Canol.

Not all of the staggering volume is recoverable — the N.W.T government estimates between two and three billion barrels is recoverable, which would rival in size the Bakken, a major shale oil region that underlies parts of North Dakota, Montana and Saskatchewan. But the promise of fresh discoveries located close to existing infrastructure has nonetheless lured oil majors including Shell, ExxonMobil Corp., Imperial Oil Ltd., ConocoPhillips Canada and Husky Energy Inc. to the northern region.

Together with MGM, the international giants have spent more than $600-million since 2011 snapping up promising acreage in the shale play, stirring hopes that the N.W.T. is poised for a petroleum revival akin to the sudden explosion of crude production that has choked pipelines and battered oil sands producers’ bottom lines further to the south.

“It’s been fairly quiet around there for the last couple of years, really,” said Doug Matthews, a Calgary-based energy consultant and former director of minerals, oil and gas for the territorial government.

“People had high expectations for the Mackenzie Gas Project and that clearly is not going to happen, so the possibility of shale exploration, regardless of actual production … has really got the folks in the area all fired up.”

Work is set to wrap up next year on a multi-year study conducted by the Northwest Territories Geoscience Office and Aboriginal Affairs and Northern Development Canada looking at the oil and gas potential of the region to the north and south of Norman Wells, where Imperial Oil first struck oil in the 1920s.

The historic Norman Wells oil field has produced more than 226 million barrels of light sweet crude in 90 years, according to the local historical society.

It now faces terminal decline, to such a degree that Enbridge Inc.’s 870-kilometre pipeline south to Zama, Alta., is running more than half empty, according to MGM’s Mr. Hogg.

MGM is preparing for a winter exploration campaign that includes drilling one well more than 2,000 metres into the budding shale play, on a prospect called East MacKay roughly 23 kilometres south of the hamlet of Tulita.

Rock-splintering injections of “frack” fluid are planned to help MGM better understand how much oil the brittle shale might yield.

The work is complicated by harsh weather and a convoluted regulatory system. It took as many as 12 months to get permits required to drill a single vertical test well, Mr. Hogg said. A similar proposal in Alberta might take four weeks to get approval, he pointed out.

Hauling equipment from Alberta also eats up more than a third of what it costs to sink a well in the permafrost, Mr. Hogg said. He said per-well costs easily run into the “tens of millions of dollars.”

Infrastructure needed to support drilling activity in the North is “minimalistic at best,” said Mr. Hogg, who previously worked as manager of frontier exploration with the Canadian unit of ConocoPhillips.

“You’re relying on winter ice road access,” he said. “I’m pulling a rig up from Alberta on an ice road that starts in Wrigley [N.W.T] and goes for another 600 kilometers.”

The long road to commercial production in the Canol – at this point still a distant prospect – has not deterred the biggest spenders in the region.

Calgary-based Husky has said little about its Arctic expedition since spending more than $376-million in a 2011 land auction for two parcels 55 kilometres southwest of Norman Wells.

Already, however, the company is evaluating construction of an all-season road to service two vertical appraisal wells drilled there early last year, a spokesperson said via e-mail.

“We know the hydrocarbons are there … but this is a difficult operating environment; it’s remote and we have our work cut out for us,” Rob Peabody, Husky’s chief operating officer, said at the company’s investor day Dec. 4. “It’s early days and we will proceed cautiously.”

Such restraint is warranted. MGM, which has partnered with Shell on another Canol prospect, last year withdrew an application for permits needed to drill a horizontal well in the formation, citing “a regulatory process that is uncertain both in terms of requirements and time lines, and thus cost.”

There is also the matter of infrastructure. If the Canol proves to be a northern counterpart to the shale bonanza under way across much of the United States and, increasingly, Western Canada, producers could well face a pipeline squeeze, observers say.

“We’re already seeing that in southern Canada, in Alberta for example,” Mr. Matthews said. “You can’t get the bitumen out of the province, and that’s a big issue that the federal government has to take a lead on, because if you can’t get the bitumen out of Alberta, how the hell are you going to get the shale out of the N.W.T.?”

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